Multiple well treatment fluid distribution and control system and method

ABSTRACT

A system for distributing fluid to a plurality of wellbores drilled from a common pad includes at least two fluid conduits extending between the wellbores. The fluid conduits are configured to couple at one end to a fluid pump. At least one remotely operable valve is hydraulically connected to each fluid conduit proximate each wellbore. At least one flow line hydraulically connects each remotely operable valve to each wellbore such that fluid moved through the flow line enters the wellbore. A control unit is disposed proximate the pad and is configured to operate the remotely operable valves.

CROSS-REFERENCE TO RELATED APPLICATIONS

Priority is claimed from U.S. Provisional Application No. 61/231,252filed on Aug. 4, 2009.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND OF THE INVENTION

1. Field of the Invention

The invention relates generally to the field of fluid treatment ofwellbores drilled through subsurface rock formations. More particularly,the invention relates to systems for controlling distribution oftreatment fluid to multiple wells drilled from a common surface pad orplatform.

2. Background Art

Wellbores drilled through subsurface rock formations to extract oil andgas may be treated by pumping various types of fluids into theformations. Fluid pumping treatments include, for example, hydraulicfracturing, wherein fluid is pumped into the formation at pressure thatexceed the fracture pressure of the formations. The fractures thusopened may be held open by pumping of material (proppant) that supportsthe fracture structurally after the fluid pressure on the formation isrelieved. Other fluid treatments may include, for example, pumping acidinto the wellbore to dissolve certain minerals present in the porespaces of the formations that reduce the formation permeability.

Certain types of rock formations that hold oil and/or gas reservoirs mayhave a plurality of wellbores drilled through the rock formations alongselected trajectories deviated from vertical, or even substantiallyhorizontally. Such wellbores may be drilled, for example, so that thesurface locations of the wellbores are closely spaced on a relativelysmall land area called a “pad”, or on a structure in the water called a“platform” in marine environments, while the lowermost portions of thewellbore extend laterally from the respective surface locations in aselected drainage pattern. Such arrangement reduces or minimizes theamount of land surface affected by the construction of the wellbores.

In conducting fluid pumping treatments on multiple wells drilled from acommon surface pad or platform, it is generally necessary to connect thepumping equipment hydraulically to one well, pump the fluid, thendisconnect the pumping equipment from the well before another well canbe fluid treated. Such operations can create, among other exposures,safety risks to personnel working on or near the pad or platform, andinterference with the operation of wellbores that are producing oiland/or gas while the fluid treatment equipment is connected anddisconnected from various wellbores on the pad or platform. Suchconnection and disconnection operations may also take considerableamounts of time to perform.

Limitations of the current state of the art design may include thefollowing. Current piping configurations for fracture treatment can havemany limitations in wells requiring multiple completed intervals and onpads with multiple wellheads. The common land fracturing configurationinvolves laying pipe from each “frac pumper” to a central collectionmanifold and then in single or multiple lines to the well being treated.The result is that a costly separate rig-up and rig down is required forevery fracture treatment.

In many applications, a single stimulation is not sufficient, andmultiple stimulations of different intervals are required. On pads withmultiple wells, if a problem is encountered on a well while there arestill intervals to stimulated, a significant cost can be incurred. Also,the problem must be solved before the stimulation can continue,resulting in the stimulation equipment waiting until the problem isresolved. In the case of a problem with a barrier between the intervalsto stimulate, this can cause a very expensive delay of multiple days, ora complete demobilization of the pumping equipment.

What is needed is a system that enables selective connection of fluidtreatment equipment to multiple wells having surface locations on a pad,platform or similar surface arrangement without the need for humanintervention near the well surface control equipment (“wellhead”), andthat can provide increased fluid pumping capacity, can save time, enablemore treatments to be accomplished in shorter time and reduces potentialfor spills. It is desirable that such system has sensing devices todetermine whether any system components have eroded as a result of fluidflow, so that the system operator can determine when it is necessary toreplace affected system components or reroute flow through alternateconduits when and if needed.

SUMMARY OF THE INVENTION

A system according to one aspect of the invention for distributing fluidto a plurality of wellbores drilled from a common pad includes at leasttwo fluid conduits extending between the wellbores. The fluid conduitsare configured to couple at one end to a fluid pumping system of one ormore pumps. At least one remotely operable valve is hydraulicallyconnected to each fluid conduit proximate each wellbore. A flow linehydraulically connects each remotely operable valve to each wellboresuch that fluid moved through the flow line enters the wellbore. Acontrol unit is disposed proximate the pad and is configured to operatethe remotely operable valves.

A method according to another aspect of the invention for operating aplurality of wellbores drilled from a common pad, wherein the wellboresinclude at least two fluid conduits extending between the wellbores, thefluid conduits configured to couple at one end to a fluid pump; at leastone remotely operable valve hydraulically connected to each fluidconduit proximate each wellbore, a flow line hydraulically connectingeach remotely operable valve to each wellbore such that fluid movedthrough the flow line enters the wellbore, and a control unit disposedproximate the pad and configured to operate the remotely operable valvesincludes the following. A wellbore intervention device is moved to aselected one of the wellbores. A signal is communicated from the controlunit to close the remotely operable valves associated with the selectedwellbore. At least one wellbore instrument is inserted into the selectedone of the wellbores using the intervention device. A signal from thecontrol unit is communicated to open at least one of the remotelyoperable valves at least one other wellbore. Fluid is pumped into onesof the at least two conduits associated with the opened remotelyoperable valves such that fluid enters the at least one other wellbore.

Other aspects and advantages of the invention will be apparent from thefollowing description and the appended claims.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows schematically an example treatment fluid distributionsystem.

FIG. 2 shows a more detailed view of a wellhead shown in FIG. 1.

DETAILED DESCRIPTION

An example well treatment fluid distribution and control system is shownschematically in FIG. 1. The system 11 may be hydraulically connected toa plurality of wells drilled through subsurface rock formations from acommon “pad” or platform 10. The pad 10 is arranged such that thesurface locations of the wellbores are proximate each other. The pad 10may be, for example, an area of the land surface clear, leveled andconfigured for equipment access to the various wellbores, or as anotherexample may be a bottom supported or floating marine (water based)platform. An example spacing between surface locations of the wellboresis about 3 meters, although the exact spacing is not intended to limitthe scope of the present invention. Well surface positions spacings areknown to vary between three to fifteen or more meters in such paddrilling arrangements. As is known in the art, wellbores drilled throughsubsurface locations typically include a pipe or “casing” emplaced inthe wellbore along part or all of the wellbore. A set of control valvesand pressure isolating devices, called a “wellhead” 12 is coupled to thesurface end of such pipe or casing on each such wellbore. An example ofthe wellhead 12 will be shown in more detail and explained further belowwith reference to FIG. 2. The example shown in FIG. 1 includes wellheads12 disposed in two lines or rows, however, the number of wellheads onany pad or platform and their particular geometric arrangement are notlimits on the scope of the present invention.

In some examples, the wellbores (shown in FIG. 2) may be initiallydrilled from the surface substantially vertically and may at a selecteddepth be have the wellbore trajectory change so that the well isultimately drilled at high inclination or substantially horizontally toenable the wellbores to provide a selected reservoir drainage pattern.The trajectory of any of the individual wellbores, however is not alimit on the scope of the present invention.

A first fluid manifold line 24 may extend along the pad 10 from a maincontrol valve 22 disposed at one end of the first manifold line 24substantially to the longitudinal position of a furthest wellhead 12 onthe pad 10. Similarly, a second fluid manifold line 26 may extend from amain control valve 22 at one end to the longitudinal position of thefurthest wellhead 12. During fluid treatment operations, a pumping unit28 may be disposed at one end of the pad 10 as shown. Typically, thepumping unit 28 will be removed from the pad 10 at times when fluidtreatment operations are not underway. During such times, the maincontrol valves 22 will be closed, and the ends of the first 24 andsecond 26 manifold lines may be hydraulically closed by closing the maincontrol valves 22. Although not shown in FIG. 1, the manifold lines 24,26 may be assembled from segments (“joints”) of conduit or tubing. Theinterconnection between joints may be any type known in the artincluding, without limitation, flanges, threads, hammer unions andwelding. The manifold lines 24, 26 preferably extend from proximate oneend of the pad 10 (to enable coupling to the pumping unit 28) to aposition proximate the most distant one of the wellheads 12. The pumpingunit 28 may be, for example, an hydraulic fracture pumping unit, an acidpumping unit, or any other wellbore fluid pumping unit known in the artfor introducing fluid under pressure into a wellbore drilled throughsubsurface rock formations.

Proximate the position of each wellhead, a “T” or “Y” fluid coupling 20may be disposed in each manifold line 24, 26 to provide at least onefluid outlet to each wellhead 12 from each manifold line 24, 26. Thus,each of the two manifold lines 24, 26 will have an individual hydraulicconnection to each wellhead 12. Connection from the fluid coupling 20 inthe first manifold line 24 to the wellhead 12 may be obtained using afirst remotely operable control valve 18, and for safety and backuppurposes a first manually operated control valve 16 coupled to thewellhead through a first treatment fluid flow line 14. The firstremotely operable control valves 18 may be, for example, hydraulicallycontrolled, electrically controlled (using cable or using wirelesscontrol) or operated by any other device that enables control of thevalve from a location remote from the location of the valve. In otherexamples, the manual control valves 16 may also be remotely operable. Itis only necessary for purposes of the invention to have one remotelyoperable valve between the manifold line 24 and the wellhead 12. Thefirst flow line 14 may be, for example, flexible hose, flexible metalline, formed rigid metal line or other type of line used in hydraulicfracturing operations known as a “chicksan.” It is preferable for thefirst flow line 14 to have smooth bends to avoid as far as practicalabrupt changes in flow direction.

In the present example, the second manifold line 26 may be hydraulicallyconnected to each wellhead 12 through a fluid coupling 20 andcorresponding second remotely operable valve 19, second manual valve 17and second flow line 15. Each of the foregoing components may be similarin configuration to the respective first remotely operable valves 18,manual valves 16 and flow lines 14. The second remotely operable valves19 and the first remotely operable valves 18 may be operated remotelyfrom a control unit 30 having suitable devices (not shown separately),for example, a suitably programmed computer with associated devicedrivers to actuate the device (not shown separately) that enables theremotely operable valves 18, 19 to be opened and closed remotely. Aswill be further explained below, the control unit 30 may also beconfigured to interrogate sensors in signal communication with thecontrol unit 30 so that the system operator may determine various systemoperating and condition parameters.

In other examples of a system, more than two manifold lines andassociated wellhead connecting equipment as described above may be used.For example, if the required fluid flow rates may exceed the flowcapacity of two manifold lines, one or more additional manifold linesmay be used substantially as explained above, preferably with a maincontrol valve at one longitudinal end, a T or Y coupling proximate eachwellhead location, a remotely operable valve and a flow line.

The system 11 shown in FIG. 1 may enable selective pumping of fluid fromthe pumping unit 28 to any or all of the wellbores through therespective wellheads 12 by suitable operation of the remotely operablevalves 18, 19. If a particular wellbore, for example, requires largefluid flow volume for the type of fluid treatment, then for suchwellbore, both the first remotely operable valve 18 and the secondremotely operable valve 19 may be opened. In the event of failure of aparticular remotely operable valve, for example the first remotelyoperable valve 18, it is possible to pump fluid into the wellhead 12through the second remotely operable valve 19. It is also possible torepair or replace individual remotely operable valves 18, 19 by closingthe respective manual valve 16, 17, closing all the other remotelyoperable valves 18, 19 connected to the respective manifold line 24, 26and the main control valve 22 associated with the respective manifoldline so that pressure may be relieved therefrom.

FIG. 1 also shows a well intervention device 50, such as a coiled tubingunit, including a reel 52 and guide rollers 52 that enable coiled tubing53 to be inserted into one of the wellbores through suitable pressurecontrol equipment (not shown) coupled to the top of the wellhead 12.Other well intervention devices may include, without limitation,wireline units, snubbing units and workover rigs. The functionsperformed by the well intervention device 50 as they relate to thesystem 11 will be further explained below.

FIG. 2 shows one of the wellheads 12 in more detail, as well as severaladditional components of the fluid distribution and control system. Thewellhead 12 may include master valves 34, 36 coupled to the top of thewell casing 32. The casing 32 is shown extending into the subsurfacefrom the wellhead 12 starting substantially vertically and thenextending substantially horizontally in a reservoir formation 35. Thecasing 32 may have perforations 33 disposed at a selected positionwithin the reservoir formation 35. The configuration of casing shown inFIG. 2 is only provided as an example, and is not intended to limit thescope of the present invention. The first 14 and second 15 flow linesmay be coupled to the wellhead 12 above the master valves 34, 36 using aspool 41. The spool 41 may be configured similarly to fluid couplingdevices used for hydraulic fracturing operations known as “frac heads.”Hydraulic connections to the wellhead 12 from the manifold lines 24, 26may be substantially as explained above with reference to FIG. 1. Avalve 40 may be disposed above the spool 41 to enable the wellhead 12 tobe hydraulically closed in the event wellbore intervention operationsare required (e.g., insertion of tools, coiled tubing and any otherdevices known in the art). The wellhead 12 may also include one or morewing valves 38 to enable coupling of the wellhead 12 to a productionline (not shown) for delivery of produced fluid from the wellbore.

In the present example, the flow lines 14, 15 and the manifold lines 24,26 may each include an erosion sensor 44 downstream of the bend in theflow lines 14, 15 or the coupling 20, respectively, or other places inthe flow path as required. In other examples, wherein the manifold lines24, 26 are assembled from joints as explained above, an erosion sensor44 may be disposed proximate each connection downstream in the flowdirection. The erosion sensors 44 may be, for example, target plates,acoustic sensors or electromagnetic induction sensors configured to makemeasurements and assist in predicting wear or metal loss correspondingto the wall thickness or stability of the respective flow line 14, 15 ormanifold line 26, 28. The erosion sensors 44 may be wirelessly in signalcommunication with, or may be cable (e.g., electrical and/or opticalcable) connected to the control unit (30 in FIG. 1) so that thickness ofthe respective component may be continuously monitored. In the event anyof the sensor measurements indicates that the component thickness isless than a predetermined safe amount, such component (e.g., segment ofthe flow lines 14, 15 or the manifold lines 24, 26) may be removed fromservice and replaced.

In the present example, pressure and/or temperature sensors 45 may bedisposed in the flow lines 14, 15 and/or at selected positions alongeach of the manifold lines 24, 26. The pressure and/or temperaturesensors 45 may be in signal communication with the control unit (30 inFIG. 1) using cable or wireless connection, as is the case for theerosion sensors 44. Measurement of pressure and/or temperature atselected positions within the system may enable the system operator todetermine optimum routing of pumped fluid to particular wellheads 12and/or to isolate portions of the system that may be defective or atrisk of failure.

In the present example, flow rate sensors 47 may be disposed in the flowlines 14, 15, or at selected positions along each manifold line 24, 26.The flow rate sensors may also be in signal communication with thecontrol unit (30 in FIG. 1) by wireless or cable connection.

Returning to FIG. 1, it is possible using the system 11 to perform fluidpumping into one or more wellbores while the well intervention device 50performs one or more tasks on a selected wellbore, including insertingat least one wellbore instrument into the selected wellbore. Forexample, coiled tubing may be used to convey pressure actuatedperforating guns or well tools into the wellbore, or remove proppantfrom a wellbore. Wireline units may be used to convey perforating guns,fracture treatment isolation packers and other devices for installationin the wellbore. During such operations, the remotely operable valves18, 19 associated with the wellbore having the intervention device 50working thereon may be closed. Another one or more of the wellbores mayhave the remotely operable valves 18, 19 opened by a control signal fromthe control unit 30. Fluid may be pumped into the wellbore(s) having theopened remotely operable valves 18, 19 by the pumping unit 28. The fluidmay be hydraulic fracturing fluid, for example, water or breakable gelhaving sand or ceramic particles as proppant. The fluid may be pumped instages according to well known fracturing procedures to open fracturesin the formation and insert the proppant therein to hold the fracturesopen after fluid pressure from the pumping unit 28 is relieved. It ispossible to move the intervention device 50 from wellbore to wellborewithout the need to move the pumping unit 28 or the need to move orphysically disconnect any part of the system 11 from the wellheads 12.Such operation is believed capable of saving substantial operating timeand cost, as well as increasing safety by reducing personnel operationsrelated to moving components of or modifying components of the flowsystem.

Possible benefits of a system made as described herein include thefollowing. Personnel need not be present in the wellhead area duringoperations because the system may be assembled prior to commencing anypumping operations. Such feature can significantly reduce risk by usingthe remotely valves (18, 19 in FIG. 1) to route the fluid flow along themanifold and between wellheads.

Offsite building of many of the unitized components of a fit-for-purposemanifold can be used for all the wells on a pad, with minimum timerequired on-site for final assembly. Once assembled, the fluiddistribution system can provide fluid access to each well on the padwithout significant changes in location or the flow equipment, and thusminimizes many fracturing rig-up construction activities. Activitiesinvolving equipment transport, use of cranes and forklifts are reduced,and vehicular traffic, human presence and construction noise areminimized.

Using a pre-built system uses less of the pad area and uses only onesite and mobilization/demobilization route on and off the pad for thefluid pumping unit. This allows a smaller footprint for the fluidpumping unit.

A permanently installed system as described above can eliminate spillsof treating fluid that can occur during disassembly of ordinarytreatment fluid equipment that is disconnected from the wellhead at theend of pumping operations when wells are treated one at a time.

A permanently installed system using the manifold-to-wellhead connectionin the present example makes use of formed flow conduits to allow closespacing of wellheads without the congestion of multiple layers oftemporary piping present in ordinary treatment fluid equipment that isdisconnected from the wellhead at the end of pumping operations. Aconsistent, well known manifold arrangement will also eliminate mistakesin fluid routing since the location of valves, lines, and sensors doesnot change from job to job.

Multiple flow distribution piping along the manifold allows routing offluids through the least restricted or lowest pressure paths and enablesswitching and isolating paths if a malfunction occurs in distributioncontrol devices, or higher rates are needed for particular applications.By having multiple paths available to the operator, pressure losses andwear in equipment can be reduced. This can be a benefit to bothoperating safety and environmental risk exposure.

Permanently instrumenting the manifold lines (24, 26 in FIG. 2) tomonitor, pressure, temperature, erosion, fatigue and corrosion canfurther reduce the risk of spills and surface escape of fluids orpressure. Permanent sensors allow more secure transmission of dataduring pumping operations allowing for fewer instances of data feedinterruption and more precise control of the fluid pumping operation.These features greatly increase safety and environmental protection ofthe site.

The manifold can be hooked up to elevated wellheads, wellheads disposedin protective “houses”, low profile wellheads disposed in a “cellar”, orstandard height wellheads. The connection may be made using flexiblehoses, formed connectors, chicksans or conventional piping without theneed to move the manifold lines (24, 26 in FIG. 1).

The state of the art of plumbing wells for fracturing prior to thepresent invention has certain limitations. When multiple wells areavailable, there are certain significant advantages in customizing awell layout and piping system to reduce the cost of hydraulic fracturingon multiple wells. The present invention incorporates many novelfeatures to possibly avoid problems in using prior art designs andpromote trouble free hydraulic fracturing operations. The presentinvention can reduce or eliminates the non productive time in thecompletion operation by making other wells on the pad immediatelyavailable for stimulation in case of one well encountering a problem.

On wells with multiple stimulations with proppant there can be seriouserosion problems in the piping along the fluid movement route from thestimulation pumpers to the wellhead. Some of the contributing factors toerosion such as velocity and change in velocity are directly impacted bythe design of the piping geometry. The fracture treatment distributionsystem of the present invention can minimizes fluid velocity andtherefore reduces erosion by increasing the pipe diameter throughout themanifold design. It also minimizes changes to the fluid velocity in twoways: First, the entire manifold is designed with a minimum of pipediameter changes (i.e., the change in direction of the fluid flow isminimized by the design of the manifold). Second, where the velocitychanges cannot be avoided, the area downstream of the velocity change isdesigned for higher erosion resistance.

While the invention has been described with respect to a limited numberof embodiments, those skilled in the art, having benefit of thisdisclosure, will appreciate that other embodiments can be devised whichdo not depart from the scope of the invention as disclosed herein.Accordingly, the scope of the invention should be limited only by theattached claims.

1. A system for distributing fluid to a plurality of wellbores drilledfrom a common pad, comprising: at least two fluid conduits extendingbetween the wellbores, the fluid conduits configured to couple at oneend to at least one fluid pump; at least one remotely operable valvehydraulically connected to each fluid conduit proximate each wellbore;at least one flow line hydraulically connecting each remotely operablevalve to each wellbore such that fluid moved through the flow lineenters the wellbore; and a control unit disposed proximate the pad andconfigured to operate the remotely operable valves.
 2. The system ofclaim 1 further comprising a valve at one end of each fluid conduit. 3.The system of claim 1 further comprising at least one erosion sensordisposed at a selected position along each fluid conduit, the at leastone erosion sensor in signal communication with the control unit.
 4. Thesystem of claim 1 further comprising at least one erosion sensordisposed at a selected position along each flow line, the at least oneerosion sensor in signal communication with the control unit.
 5. Thesystem of claim 1 further comprising a flow rate sensor disposed in eachflow line, the flow rate sensors in signal communication with thecontrol unit.
 6. The system of claim 1 further comprising at least oneadditional valve in each flow line disposed between the at least oneremotely operable valve and the wellbore.
 7. The system of claim 1wherein the at least one additional valve is remotely operable.
 8. Amethod for operating a plurality of wellbores drilled from a common pad,wherein the wellbores include at least two fluid conduits extendingbetween the wellbores, the fluid conduits configured to couple at oneend to a fluid pump; at least one remotely operable valve hydraulicallyconnected to each fluid conduit proximate each wellbore, a flow linehydraulically connecting each remotely operable valve to each wellboresuch that fluid moved through the flow line enters the wellbore, and acontrol unit disposed proximate the pad and configured to operate theremotely operable valves, the method comprising: moving a wellboreintervention device to a selected one of the wellbores; communicating asignal from the control unit to close the remotely operable valvesassociated with the selected wellbore; inserting at least one wellboreinstrument into the selected one of the wellbores using the interventiondevice; communicating a signal from the control unit to open at leastone of the remotely operable valves at least one other wellbore; andpumping fluid into ones of the at least two conduits associated with theopened remotely operable valves such that fluid enters the at least oneother wellbore.
 9. The method of claim 8 wherein the fluid is hydraulicfracturing fluid.